Recovery From A Hydrocarbon Reservoir

ABSTRACT

Methods and systems for recovering heavy oil, such as bitumen, by steam assisted gravity drainage (SAGD) from subterranean formations having a water and/or gas containing layer overlying a heavy oil containing layer. A fluid blocking agent is injected into the water and/or gas containing layer above at least one pair of horizontal wells. The blocking agent undergoes a change of density, viscosity or solidity when elevated to a temperature between an initial ambient reservoir temperature and 175 degrees by heat from steam used in the SAGD process, thereby creating a seal within the reservoir above the at least one pair of horizontal wells limiting or preventing movements of fluid through the seal.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of Canadian PatentApplication number 2,830,741 filed Oct. 23, 2013 entitled IMPROVINGRECOVERY FROM A HYDROCARBON RESERVOIR, the entirety of which isincorporated by reference herein.

FIELD

The present disclosure relates to harvesting hydrocarbon resources usinggravity drainage processes. Specifically, improved methods are disclosedinvolving steam assisted gravity drainage of heavy oil from undergroundreservoirs.

BACKGROUND

This section is intended to introduce various aspects of the art, whichmay be associated with the present disclosure. This discussion isbelieved to assist in providing a framework to facilitate a betterunderstanding of particular aspects of the present disclosure.Accordingly, it should be understood that this section should be read inthis light, and not necessarily as admissions of prior art.

Modern society is greatly dependent on the use of hydrocarbons for fuelsand chemical feedstocks. Hydrocarbons are generally found in subsurfacerock formations that can be termed “reservoirs.” Removing hydrocarbonsfrom the reservoirs depends on numerous physical properties of the rockformations, such as the permeability of the rock, sand or soilcontaining the hydrocarbons, the ability of the hydrocarbons to flowthrough the rock, sand or soil formations, and the proportion ofhydrocarbons present, among other things.

Easily harvested sources of hydrocarbon are dwindling, leavingless-accessible sources to satisfy future energy needs. However, as thecosts of hydrocarbons increase, these less-accessible sources becomemore economically attractive. For example, the harvesting of oil sandsto remove hydrocarbons has become more extensive as it has become moreeconomical. The hydrocarbons harvested from these reservoirs may haverelatively high viscosities, for example, ranging from 8 degrees API, orlower, up to 20 degrees API, or higher. Accordingly, the hydrocarbonsmay include heavy oils, bitumen, or other carbonaceous materials,collectively referred to herein as “heavy oil,” which are difficult torecover using standard techniques.

Several methods have been developed to remove hydrocarbons fromreservoirs oil sands. For example, strip or surface mining may beperformed to access the oil sands, which can then be treated with hotwater or steam to extract the oil. However, deeper formations may not beaccessible using a strip mining approach. For these formations, a wellcan be drilled into the reservoir and steam, hot air, solvents, orcombinations thereof, can be injected to release the hydrocarbons. Thereleased hydrocarbons may then be collected by the injection well or byother wells (i.e. production wells) and brought to the surface.

A number of techniques have been developed for harvesting heavy oil fromsubsurface formations using well-based recovery techniques. Theseoperations include a suite of steam based in-situ thermal recoverytechniques, such as cyclic steam stimulation (CSS), steam flooding andsteam assisted gravity drainage (SAGD) as well as surface mining andtheir associated thermal based surface extraction techniques.

Various embodiments of the SAGD process are described in Canadian PatentNo. 1,304,287 to Butler and U.S. Pat. No. 4,344,485. In SAGD, twohorizontal wells are completed into the reservoir. The two wells arefirst drilled vertically to different depths within the reservoir.Thereafter, using directional drilling technology, the two wells areextended in the horizontal direction that result in two horizontalwells, vertically spaced from, but otherwise vertically aligned with theother. Ideally, the production well is located above the base of thereservoir but as close as practical to the bottom of the reservoir, andthe injection well is located vertically 10 to 30 feet (3 to 10 meters)above the horizontal well used for production.

The upper horizontal well is utilized as an injection well and issupplied with steam from the surface. The steam rises from the injectionwell, permeating the reservoir to form a vapor chamber (steam chamber)that grows over time towards the top of the reservoir, therebyincreasing the temperature within the reservoir. The steam, and itscondensate, raise the temperature of the reservoir and consequentlyreduce the viscosity of the heavy oil in the reservoir. The heavy oiland condensed steam will then drain downwardly through the reservoirunder the action of gravity and may flow into the lower production well,from which these liquids can be pumped to the surface. At the surface ofthe well, the condensed steam and heavy oil are separated, and the heavyoil may be diluted with appropriate light hydrocarbons for transport bypipeline.

Significant portions of oil sands, at least in the Athabasca region ofCanada, have either water zones (water-containing sands) positioned ontop of the heavy oil bearing sands or have gas caps (zones ofgas-containing ground overlying the heavy oil bearing sands), orcombinations of the two (layers containing both water and gas). Thesezones may act as “thief zones” into which steam can be lost or channeledaway from the target depletion zone (the heavy oil bearing layers), orthey may cause cold water to permeate the heavy oil-bearing layers, thusreducing the reservoir temperature. This can severely degrade theperformance of SAGD processes and may be detrimental to the economics ofthe development project. Where there is a top water zone, steam willrise up into the water zone and cold water from the top water zone maydrain down into the well. Where there is a gas cap, if the gas cap is atlow pressure, this will limit the pressure of the SAGD process, and itmay not be economical to operate SAGD at such a low pressure due toconsequent lower production rates.

SUMMARY

A method of recovering heavy oil from a hydrocarbon reservoir in which awater and/or gas containing layer overlies a heavy oil containing layer,may comprise providing an injection well in the water and/or gascontaining layer above at least one pair of horizontal wells in theheavy oil containing layer for heavy oil recovery by a steam assistedgravity drainage process, injecting a blocking agent into the waterand/or gas containing layer via the injection well to form a region ofthe water and/or gas containing layer containing the blocking agentadjacent an interface between the water and/or gas containing layer andthe heavy oil containing layer above the at least one pair of horizontalwells, and operating the steam assisted gravity drainage process via theat least one pair of wells by injecting steam into the heavy oilcontaining layer and recovering heavy oil from the heavy oil containinglayer. The blocking agent is injected into the water and/or gascontaining layer before operating the steam assisted gravity drainageprocess or before heat generated by the steam assisted gravity drainageprocess reaches the region of the water and/or gas containing layer thatwill contain the blocking agent. The blocking agent, when present in theregion, undergoes a change of viscosity, density or solidity whenelevated to a temperature between an initial ambient reservoirtemperature in the region and 175° C. by heat from steam used in theprocess, and thereby creates a seal within the reservoir above the atleast one pair of horizontal wells limiting or preventing movements offluid through the seal.

The foregoing has broadly outlined the features of the presentdisclosure so that the detailed description that follows may be betterunderstood. Additional features will also be described herein.

DESCRIPTION OF THE DRAWINGS

These and other features, aspects and advantages of the presentdisclosure will become apparent from the following description,appending claims and the accompanying drawings, which are brieflydiscussed below.

FIG. 1 is a drawing of a steam assisted gravity drainage process.

FIGS. 2A to 2D illustrate steps in a method of heavy oil recovery.

FIGS. 3A and 3B illustrate steps in a method of heavy oil recovery.

It should be noted that the figures are merely examples and nolimitations on the scope of the present disclosure are intended thereby.Further, the figures are generally not drawn to scale, but are draftedfor the purpose of convenience and clarity in illustrating variousaspects of the disclosure.

DETAILED DESCRIPTION

For the purpose of promoting an understanding of the principles of thedisclosure, reference will now be made to the features illustrated inthe drawings and specific language will be used to describe the same. Itwill nevertheless be understood that no limitation of the scope of thedisclosure is thereby intended. Any alterations and furthermodifications, and any further applications of the principles of thedisclosure as described herein are contemplated as would normally occurto one skilled in the art to which the disclosure relates. It will beapparent to those skilled in the relevant art that some features thatare not relevant to the present disclosure may not be shown in thedrawings for the sake of clarity.

At the outset, for ease of reference, certain terms used in thisapplication and their meanings as used in this context are set forth. Tothe extent a term used herein is not defined below, it should be giventhe broadest definition persons in the pertinent art have given thatterm. Further, the present techniques are not limited by the usage ofthe terms shown below, as all equivalents, synonyms, new developments,and terms or techniques that serve the same or a similar purpose areconsidered to be within the scope of the present claims.

“Bitumen” is a naturally occurring heavy oil material. Generally, it isthe hydrocarbon component found in oil sands. Bitumen can vary incomposition depending upon the degree of loss of more volatilecomponents. It can vary from a very viscous, tar-like, semi-solidmaterial to solid forms. The hydrocarbon types found in bitumen caninclude aliphatics, aromatics, resins, and asphaltenes. A typicalbitumen might be composed of: 19 wt. % aliphatics (which can range from5 wt. %-30 wt. %, or higher); 19 wt. % asphaltenes (which can range from5 wt. %-30 wt. %, or higher); 30 wt. % aromatics (which can range from15 wt. %-50 wt. %, or higher); 32 wt. % resins (which can range from 15wt. %-50 wt. %, or higher); and some amount of sulfur (which can rangein excess of 7 wt. %). In addition bitumen can contain some water andnitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7wt. %. The metals content, while small, must be removed to avoidcontamination of the product synthetic crude oil (SCO). Nickel can varyfrom less than 75 ppm (part per million) to more than 200 ppm. Vanadiumcan range from less than 200 ppm to more than 500 ppm. The percentage ofthe hydrocarbon types found in bitumen can vary. As used herein, theterm “heavy oil” includes bitumen, as well as lighter materials that maybe found in a sand or carbonate reservoir. Heavy oil may have aviscosity of about 1000 cP or more, 10,000 cP or more, 100,000 cP ormore or 1,000,000 cP or more.

As used herein, two locations in a reservoir are in “fluidcommunication” when a path for fluid flow exists between the locations.For example, fluid communication between a production well and anoverlying steam chamber can allow mobilized material to flow down to theproduction well for collection and production. As used herein, a fluidincludes a gas or a liquid and may include, for example, a producedhydrocarbon, an injected mobilizing fluid, or water, among othermaterials.

“Facility” as used in this description is a tangible piece of physicalequipment through which hydrocarbon fluids are either produced from areservoir or injected into a reservoir, or equipment which can be usedto control production or completion operations. In its broadest sense,the term facility is applied to any equipment that may be present alongthe flow path between a reservoir and its delivery outlets. Facilitiesmay comprise production wells, injection wells, well tubulars, wellheadequipment, gathering lines, manifolds, pumps, compressors, separators,surface flow lines, steam generation plants, processing plants, anddelivery outlets. In some instances, the term “surface facility” is usedto distinguish those facilities other than wells.

“Heavy oil” includes oils which are classified by the American PetroleumInstitute (API), as heavy oils, extra heavy oils, or bitumens. Thus theterm “heavy oil” includes bitumen and should be regarded as suchthroughout this description. In general, a heavy oil has an API gravitybetween 22.30 (density of 920 kg/m³ or 0.920 g/cm³) and 10.00° (densityof 1,000 kg/m³ or 1 g/cm). An extra heavy oil, in general, has an APIgravity of less than 10.00° (density greater than 1,000 kg/m³ or greaterthan 1 g/cm). For example, a source of heavy oil includes oil sand orbituminous sand, which is a combination of clay, sand, water, andbitumen. The thermal recovery of heavy oils is based on the viscositydecrease of fluids with increasing temperature or solvent concentration.Once the viscosity is reduced, the mobilization of fluids by steam, hotwater flooding, or gravity is possible. The reduced viscosity makes thedrainage quicker and therefore directly contributes to the recoveryrate.

A “hydrocarbon” is an organic compound that primarily includes theelements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals,or any number of other elements may be present in small amounts. As usedherein, hydrocarbons generally refer to components found in heavy oil orin oil sands. However, the techniques described herein are not limitedto heavy oils, but may also be used with any number of other reservoirsto improve gravity drainage of liquids.

“Permeability” is the capacity of a rock to transmit fluids through theinterconnected pore space s of the rock. The customary unit ofmeasurement for permeability is the millidarcy.

“Pressure” is the force exerted per unit area by the gas on the walls ofthe volume. Pressure may be shown in this disclosure as pounds persquare inch (psi), kilopascals (kPa) or megapascals (MPa). Unlessotherwise specified, the pressures disclosed herein are absolutepressures, i.e. the sum of gauge pressure plus atmospheric pressure(generally 14.7 psi at standard conditions).

As used herein, a “reservoir” is a subsurface rock or sand formationfrom which a production fluid, or resource, can be harvested. The rockformation may include sand, granite, silica, carbonates, clays, andorganic matter, such as bitumen, heavy oil, oil, gas, or coal, amongothers. Reservoirs can vary in thickness from less than one foot (0.3048m) to hundreds of feet (hundreds of ml. The resource is generally ahydrocarbon, such as a heavy oil impregnated into a sand bed.

As discussed herein, “Steam Assisted Gravity Drainage” (SAGD), is athermal recovery process in which steam, or combinations of steam andsolvents, is injected into a first well to lower a viscosity of a heavyoil, and fluids are recovered from a second well. Both wells aregenerally horizontal in the formation and the first well lies above thesecond well. Accordingly, the reduced viscosity heavy oil flows down tothe second well under the force of gravity, although pressuredifferential may provide some driving force in various applications.Although SAGD is used as an exemplary process herein, it can beunderstood that the techniques described can include any gravity drivenprocess, such as those based on steam, solvents, or any combinationsthereof.

“Substantial” when used in reference to a quantity or amount of amaterial, or a specific characteristic thereof, refers to an amount thatis sufficient to provide an effect that the material or characteristicwas intended to provide. The exact degree of deviation allowable may insome cases depend on the specific context.

“Thermal recovery processes” include any type of hydrocarbon recoveryprocess that uses a heat source to enhance the recovery, for example, bylowering the viscosity of a hydrocarbon. These processes may useinjected mobilizing fluids, such as hot water, wet steam, dry steam, orsolvents alone, or in any combinations, to lower the viscosity of thehydrocarbon. Such processes may include subsurface processes, such ascyclic steam stimulation (CSS), cyclic solvent stimulation, steamflooding, solvent injection, and SAGD, among others, and processes thatuse surface processing for the recovery, such as sub-surface mining andsurface mining. Any of the processes referred to herein, such as SAGD,may be used in concert with solvents.

A “wellbore” is a hole in the subsurface made by drilling or inserting aconduit into the subsurface. A wellbore may have a substantiallycircular cross section or any other cross-sectional shape, such as anoval, a square, a rectangle, a triangle, or other regular or irregularshapes. As used herein, the term “well,” when referring to an opening inthe formation, may be used interchangeably with the term “wellbore.”Further, multiple pipes may be inserted into a single wellbore, forexample, as a liner configured to allow flow from an outer chamber to aninner chamber.

“Thermally and/or chemically-activated blocking agents” are materialsthat are flowable through the porous medium of a reservoir when injectedinto the porous medium of the reservoir and that, when activated by achange of temperature or chemical reaction, solidify, densify or gel, orshed a solid precipitate, and thus block pores in the reservoir tohinder or prevent the passage of gas or water through the reservoir.

A “steam chamber” is a region of a heavy oil containing layer of areservoir that forms around a steam injection well and that is generallyat or close to the temperature of steam at the pressures within thereservoir. The chamber may comprise pores from which heavy oil has atleast partially flowed upon being heated by the steam to be replaced atleast in part by steam itself. In practice, heavy oil containing layersmay not necessary have pores containing 100% heavy oil and may naturallycontain only 70-80 vol. % heavy oil with the remainder usually water. Incontrast, a water and/or gas containing layer may comprise 100% waterand/or gas in the pores, but normally contains 5-70 vol. % gas and 20-30vol. % water with any remainder being heavy oil.

For a better understanding of the techniques of the present disclosure,a brief explanation of one form of steam assisted gravity drainage isfirst provided below.

Steam Assisted Gravity Drainage (SAGD)

SAGD may be carried out in geological formations wherein a water layeror gas cap lies above heavy oil containing strata. Good recovery ofheavy oil may be achieved by injecting a thermally and/orchemically-activated blocking agent into the water or gas layer,preferably adjacent to the heavy oil/water or gas layer interface toreduce or prevent escape of extraction steam into the water- orgas-containing layer, and to reduce or prevent leakage of water into theheavy oil strata or steam chamber produced by the extraction steam.

FIG. 1 is a drawing of a SAGD process 100 used for accessing hydrocarbonresources in a reservoir 102. In the SAGD process 100, steam 104 can beinjected through injection wells 106 to the reservoir 102. The injectionwells 106 may be horizontally drilled through the reservoir 102.Production wells 108 may be drilled horizontally through the reservoir102, with a production well 108 underlying each injection well 106. Theinjection wells 106 and production wells 108 may be drilled from thesame pad 110 at the surface 112. Drilling from the same pad 110, maymake it easier for the production well 108 to track the injection well106. Alternatively, the injection well 106 and the production 108 may bedrilled from different pads 110. For example, the injection well 106 andthe production well 108 may be drilled from different pads 110 if theproduction well 108 is an infill well.

The injection of steam 104 into the injection wells 106 may result inthe mobilization of hydrocarbons 114. Once mobilized, the hydrocarbons114 may drain to the production wells 108 and be removed to the surface112 in a mixed stream 116 that may contain hydrocarbons, condensate andother materials, such as water, gases, and the like. Sand filters may beused in the production wells 108 to decrease sand entrainment in thehydrocarbons removed to the surface 112.

A mixed stream 116 from a number of production wells 108 may be combinedand sent to a processing facility 118. At the processing facility 118,the water and hydrocarbons 120 can be separated, and the hydrocarbons120 sent on for further refining. Water from the separation may berecycled to a steam generation unit within the facility 118, with orwithout further treatment, and may be used to generate the steam 104used for the SAGD process 100.

The production wells 108 may have a segment that is relatively flat,which, in some developments, may have a slight upward slope from theheel 122, at which the pipe branches to the surface, to the toe 124, atwhich the pipe ends. When present, an upward slope of this horizontalsegment may result in the toe 124 being around one to five meters higherthan the heel 122, depending on the length of the horizontal segment.The slight slope can assist in draining fluids that enter the horizontalsegment to the heel 122 for removal.

It should be appreciated that, while one form of SAGD is describedabove, the present disclosure may relate to any and all forms of SAGD.

SAGD may be carried out in geological formations wherein a watercontaining layer (water zone) and/or a gas containing layer (gas cap)lies directly above and in contact with heavy oil containing strata,e.g. layer 102 of FIG. 1. Good recovery of heavy oil may be achieved byinjecting a blocking agent into the water and/or gas containing layer toreduce or prevent escape of extraction steam into the water and/or gascontaining layer, and/or to reduce or prevent leakage of water from thewater and/or gas containing layer into the heavy oil strata or steamchamber produced by the extraction steam.

A variety of materials, both aqueous and non-aqueous, may be employed asblocking agents. The blocking agents may be employed singly or incombination, as will be described later. The blocking agents may undergoa transformation when in situ in a reservoir formation from a form inwhich the blocking agents may freely penetrate a permeable region of arock, sand or soil substrate, to a form in which the blocking agentsprevent or substantially limit the movement of fluids through the regionthat they have penetrated. When the blocking agents assume this form,they have become a seal limiting or preventing fluid flow through theaffected substrate. The blocking agents may be chosen fromthermally-activated and chemically-activated blocking agents. Someblocking agents may undergo activation by both thermal and chemicaleffects.

Thermally-activated blocking agents may be fluids, generally liquids.When ready for injection into water and/or gas containing layers, onetype of thermally activated blocking agents may be at ambienttemperatures (temperatures that are ambient at the surface, e.g.nominally 21° C.), or at initial ambient temperatures within thereservoir where they are to be injected (temperatures before the startof recovery processes, generally 6 to 15° C.). The thermally activatedblocking agents of this type may undergo a transformation at highertemperatures, e.g. at temperatures between ambient and 175° C., forexample, ambient up to 125° C. or ambient up to 100° C., after which theblocking agents exhibit higher viscosity, density or solidity (e.g. forma precipitate or become solid). The thermally activated blocking agentsof this type may contain compounds that exhibit inverse solubilitycharacteristics. In other words, the thermally activated blocking agentsmay contain compounds that are less soluble in solvents at highertemperatures than at lower temperatures, so that solutions of thesecompounds may have low viscosity at low temperature but may formprecipitates or gels or solids or glasses, etc., at higher temperatures.The thermally activated blocking agents of this type may rely onabsorbing heat for activation when present in a reservoir. The thermallyactivated blocking agents may absorb heat from steam used for SAGD.

Other types of thermally-activated blocking agents may include thosecontaining compounds having normal solubility characteristics, i.e.compounds that become more soluble in solvents as temperature increases,or conversely and more importantly, compounds that become less solublein solvents as the temperature decreases. As a result, the compoundshaving normal solubility characteristics may precipitate out of solutionas the temperature of the solution falls. The thermally-activatedblocking agents of these types may be prepared or obtained as saturatedor supersaturated solutions at high temperatures (e.g. 80° C. or higher)and are injected into the reservoir at such high temperatures. As thesaturated or supersaturated solutions encounter and penetrate reservoirsubstrates having lower temperatures than the injected saturated orsupersaturated solutions (i.e. initial reservoir ambient temperatures ofe.g. 6 to 15° C.), the saturated or supersaturated solutions areactivated by forming solid or semi-solid precipitates that act to blockpores and interstices in the rock, sand or soil substrate. Therefore, inthis way, the blocking agents are thermally-activated, but by coolingrather than by heating.

Chemically-activated blocking agents may be compounds or compositionsthat are fluids, e.g. liquids, of suitably low viscosity that they mayfreely penetrate a region of the rock, sand or soil of a reservoirformation, but that undergo a chemical transformation when in situ inthe penetrated region upon encountering one or more chemicals presentin, or generated within, or introduced into, the formation. The chemicaltransformation causes an increase of viscosity, density or solidity sothat the chemically activated blocking agent then prevents or limits themovements of fluids through the region that the fluids occupy. Forexample, chemically-activated blocking agents may be reactive with gasesor acids produced in a heavy-oil containing layer upon exposure of theheavy oil or the substrate to the temperatures employed during SAGD. Forexample, thermolysis of components of the heavy oil may produce carbondioxide or hydrogen sulfide that may then contact and react with thechemically activated blocking agents to cause the indicatedtransformations.

When a single blocking agent is employed, the blocking agent may be athermally-activated blocking agent that undergoes a transformation as itabsorbs heat from steam used in a SAGD process. When at least onefurther blocking agent is employed (i.e. two or more blocking agents), athermally-activated blocking agent (i.e., a first blocking agent) mayfirst be injected into the water and/or gas containing layer so that thethermally-activated blocking agent occupies a region close to theinterface between the water and/or gas containing layer and the heavyoil containing layer. The thermally-activated blocking agent is,therefore, close to the steam chamber created during SAGD and receivesheat from the steam for the transformation required by thethermally-activated blocking agent to form a seal. After injecting thefirst blocking agent, a second blocking agent may then be injected intothe formation to occupy a second region above and/or surrounding thefirst region occupied by the first blocking agent. The second blockingagent may be one that does not require heat from the steam to undergoits required transformation. The second blocking agent may notnecessarily have to be positioned as close to the steam chamber becauseit does not require heat. The second blocking agent may therefore be athermally-activated blocking agent of the kind containing a compoundhaving normal solubility characteristics that is injected hot andundergoes a transformation as it cools, or it may be achemically-activated blocking agent that reacts with gases or fluidspresent in, or generated within, the formation. An advantage of using asecond blocking agent of one of these kinds is that the second blockingagent may extend the area or thickness of the blocking seal beyond thezone penetrated by heat from the steam that is required fortransformation of the first-injected blocking agent. Of course, a thirdor even more blocking agents may be injected into the formation tofurther extend the area or thickness of the blocking seal, but possiblyat the expense of increased cost and/or diminishing effectiveness. Ifsuch a third or more blocking agent is employed, it may also be one thatdoes not require heat from the steam to undergo transformation.

When a second blocking agent is employed, it may be injected into thewater and/or gas containing layer at any time, e.g. during commencementof the SAGD process, during start-up of the SAGD process, or duringoperation of the SAGD process.

Examples of thermally-activated blocking agents of the type havinginverse solubility characteristics include, but are not limited to,aqueous solutions of sodium silicate and aqueous solutions of calciumbicarbonate. When subjected to heating, sodium silicate forms a gel orglass-like solid that forms an effective seal. Calcium bicarbonate, incontrast, tends to deposit a solid precipitate that forms a seal.Colloidal silica may also be effective as it may form a gel at anelevated temperature.

As an example, solutions of sodium silicate may be injected into a waterand/or gas containing layer to penetrate a region of the water and/orgas containing layer and may remain in liquid form for prolonged periodsof time at normal ambient reservoir temperatures. However, when heatedby heat from a steam chamber created during SAGD, the solutions, after acertain period of time (hours to days or even months), form a glass-likegel that significantly reduces the effective permeability of the rock,sand or soil so that fluids can no longer flow through the rock, sand orsoil, thereby forming an effective barrier acting as a seal. Theglass-like gel may have good stability at the temperatures encountered,with little tendency to degrade, so that the seal remains effective andin place for a suitably long time, even for the duration of the SAGDprocess and possibly for the full productive life of the SAGD wells,which may be from 10 to 30 years. Of course, if the seal is found tobreak down or leak over time during the SAGD process, furtherthermally-activated blocking agent may be introduced through theblocking agent injection well to supplement or repair the seal asrequired.

Sodium silicate is the common name for the compound sodium metasilicate,Na₂SiO₃ or (SiO₂)_(n):Na₂O, sometimes known as waterglass. It isavailable commercially as an alkaline aqueous solution (pH 11-13) havingwater-like viscosity, as well as in solid form that may be dissolved inwater. Upon exposure to heat, the sodium silicate forms silicaaggregates or polymers creating a gel that reduces the permeability ofporous rock, soil or sand. Chelating agents (e.g. ethylenediaminetetracetic acid (EDTA) or nitrilotriacetic acid (NTA)) and/or acids(e.g. 6.5 vol. % HCl) may be added to the sodium silicate solution tohelp the material set or solidify in the presence of heat. The gelformation may take from several minutes to several months depending ontemperature conditions and additives. A liquid form of sodium silicatemay be obtained, for example, from BIM Norway under the trademarkKrystazil 40. This product has a (SiO₂)_(n):Na₂O ratio of 3.4, a pH of11.5 and a concentration of 27.6 wt %. Before use, it may be dilutedwith water (e.g. to about 4 wt. %) and provided with a pH activator(e.g. HCl added under agitation in an amount of wt. % of the 2.0 M HClstock solution). Further information about suitable sodium silicate gelsystems and their preparation may be obtained from the followingpublication, the disclosure of which is incorporated herein byreference:

-   Burns L., et al., “New Generation Silicate Gel System for Casing    Repairs and Water Shutoff”, Society of Petroleum Engineers, SPE    113490, presented at 2008 SPE/DOE Improved Oil Recovery Symposium    held in Tulsa, Okla., U.S.A., 19-23 Apr., 2008.    The Burns publication describes sodium silicate solutions containing    partially hydrolyzed polyacrylamide used in combination with a    silica polymer gel initiator and employing an organic initiator.

While sodium silicate is described above as a thermally-activatedblocking agent of the kind having inverse solubility characteristics, itmay also operate as a chemically-activated blocking agent. Sodiumsilicate may operate as a chemically-activated blocking agent because itmay react with available carbon dioxide (produced, for example, by heavyoil thermolysis during SAGD) to form silica gel and a glass-like sodiumcarbonate, e.g. by the following reaction:

Na₂Si₂O₅.H₂O_((liquid))+CO_(2(gas))→SiO_(2(gel))+Na₂CO₃.H₂O_((glass))

Colloidal silica, which is another example of a thermally-activatedblocking agent of the kind having inverse solubility characteristics,forms a colloidal solution (sol) or gel when subjected to heat fromsteam used in the SAGD process. Further details of the preparation andcharacteristics of colloidal silica may be obtained from the followingpublication, the disclosure of which is incorporated herein byreference:

-   Jurinak J. J. et al., “Oilfield Applications of Colloidal Silica    Gel”, Production Engineering, November 1991, pp. 406-412.    As noted above, calcium bicarbonate, which is another example of a    thermally-activated blocking agent having inverse solubility    characteristics, reacts with heat to deposit calcium carbonate    according to the reaction below:

Ca²+(aq)+2HCO₃−(aq)→CaCO₃(s)+H₂O+CO₂(l)

or

Ca(HCO₃)₂→CO₂(g)+H₂O(l)+CaCO₃(s).

More information about calcium carbonate deposits may be obtained fromthe following publication, the disclosure of which is incorporatedherein by reference:

-   John E. Oddo, et al., “Simplified Calculation of CaCO ₃ Saturation    at High Temperatures and Pressures in Brine Solution”, Journal of    Petroleum Technology, Vol. 34, No. 7, pp. 1583-1590, July 1982.

An example of a material that may be suitable as a thermally- and/orchemically-activated blocking agent according to this disclosure is asolution of silica (SiO₂). Solutions of silica are typically removedfrom boiler feed water as a waste and are consequently inexpensive.Unlike sodium silicate or calcium bicarbonate, silica exhibits normalsolubility characteristics in that its solubility increases or decreaseswith temperature increase or decrease, respectively. Soluble silica athigh temperature precipitates out of solution when its temperatureand/or pH is lowered. Soluble silica may be employed as a blocking agentby, for example:

-   -   a) Injecting water with a high silica concentration (e.g. a        saturated or supersaturated solution) at high temperature (e.g.        80° C. or higher) into the reservoir so that, as the solution        cools as it encounters ambient temperatures within the        reservoir, SiO₂ precipitates from the solution, thereby forming        a seal and blocking movement of steam or water into or from the        water and/or gas containing layer. If steam does break through        the resulting seal, acid gases (e.g. CO₂) formed by        aqua-thermolysis within the heavy oil-bearing layer will be        carried along with the steam. This escape of steam and acid        gases may lower the pH of the injected silica solution and        thereby initiate further precipitation of the silica. Silica        solutions having a high silica concentration are useful as        second (or later) blocking agents injected after a first        blocking agent activated by heat from steam used for the SAGD        process.    -   b) Injecting water with a high concentration of Ca, Mg or Fe as        well as silica into the formation so that, as heat is        encountered from the approaching steam chamber, insoluble Ca, Mg        or Fe silicates or a combination thereof will form, again        producing a seal and blocking the advancement of steam into the        water and/or gas containing layer. Sodium-iron silicates may        also be formed from sodium made available in the injected        solution or present in the connate water. Silica solutions        containing high concentrations of Ca, Mg or Fe may be used as a        sole blocking agent (or the first of two or several) as they are        activated by heat from the steam used for the SAGD process.

The amount or volume of the thermally- and/or chemically-activatedblocking agent injected into the water and/or gas containing layer maybe sufficient to form a penetrated region of effective extent to form agas and/or water seal above the SAGD wells and the steam chamber createdby the injection of steam. The required amount of the thermally- and/orchemically-activated blocking agent may vary from reservoir to reservoirand from formation to formation, and/or from well to well, due todifferences of rock permeability, physical dimensions of the injectionand production wells, details of the SAGD process, etc. An effectiveamount may be determined by simple trial and experiment, or may becalculated in advance by appropriate reckoning or algorithms. Ingeneral, the amount may be sufficient to form a seal that is at least asextensive as the top area of the steam chamber formed in the heavy oilcontaining layer when in its steady state of operation. Any steam risingin the chamber is then blocked by the seal and is forced to movehorizontally into less heated structures. Suitable inflow/outflowcontrol devices may be used for the injection of the thermally- and/orchemically-activated blocking agent to achieve even distribution of thethermally- and/or chemically-activated blocking agent within the rockformation. In the case of SAGD wells that are 1000 meters long andprovided with a lateral spacing of 100 meters between adjacent wellpairs, drilled through substrate having pores forming 30% of the volumeof the substrate, and aiming for a layer thickness of one meter, thetotal targeted pore space would be about 30,000 m³. Typically, only afraction of this volume would need to be injected with the thermallyand/or chemically-activated blocking agent in order to at leastpartially contact most of the pore space. For example, between 1,000 to20,000 cubic meters of the thermally and/or chemically-activatedblocking agent may be required in such a case.

Injection criteria for each specific reservoir may be established toprevent plugging or precipitation of the thermally- and/orchemically-activated blocking agent prior to in-situ heating by thesteam used for the SAGD process. The use of pH modifiers, anti-scalantsor similar chemical additives may be employed to achieve the objectiveof preventing plugging or precipitation. Water used for the preparationof the thermally- and/or chemically-activated blocking agent may beobtained from any available source, e.g. locally on-site.

While a thermally-activated blocking agent may be injected into thewater and/or gas containing layer prior to operation of the SAGDprocess, or during SAGD start-up, as explained above, additionalthermally-activated blocking agent may be injected into the water and/orgas containing layer during operation of the SAGD process. Theadditional thermally-activated blocking agent may be injected after thesteam chamber has reached the top of the heavy oil containing layer toblock areas that may potentially provide leaks of the steam into thewater and/or gas containing layer. As the additional thermally-activatedblocking agent is being injected, the pressure of steam used for theSAGD may be temporarily lowered to draw some of the furtherthermally-activated blocking agent into the heated zone where it willsolidify and extend or repair the required seal. The steam thus confinedto the steam chamber may thus give rise to good production rates and anefficient recovery process.

As also noted above, a second blocking agent may be injected into asecond region of the water and/or gas containing layer beforecommencement of the SAGD process or during SAGD start-up. If so, furtheramounts of the second blocking agent may be injected into the waterand/or gas containing layer during these stages, or later as the SAGDprocess proceeds, to further limit movements of fluids through thesecond region. Alternatively, a second blocking agent may be injectedinto the water and/or gas containing layer for the first time as SAGDproceeds, i.e. after commencement and startup of the SAGD, ifsupplementation of the seal formed by the first blocking agent appearsto be necessary to improve or maintain heavy oil production. The secondblocking agent may be injected into the water and/or gas containinglayer (i) before commencement of the SAGD process and/or during SAGDstart-up and (ii) as SAGD proceeds (i.e., after commencement and startupof the SAGD). Further addition(s) of the second blocking agent may thenalso be made as the SAGD process proceeds further in time.

FIGS. 2A through 2D show examples of steps in which a blocking agent isemployed to create a seal between a hydrocarbon-containing layer 202 ofan oil sands formation 200 and a water-containing and/or gas-containinglayer 204 situated above the hydrocarbon-containing layer 202. As wellas providing an injection well 206 and a production well 208 in theheavy oil-containing layer 202 as in conventional SAGD, at least oneblocking agent injection well 210 is drilled into the water and/or gascontaining layer 204. The at least one blocking agent may be drilledclose to the interface 205 between layers 204 and 202. The blockingagent injection well 210 may be of similar length to the injection well206 and the production well 208, or longer. The blocking agent injectionwell 210 may be positioned directly vertically above and parallel tosuch wells.

Prior to the operation of the SAGD process or before a steam chamber 216produced by such process approaches the interface 205, a fluidthermally-activated blocking agent 212 may be injected into the waterand/or gas containing layer 204. A region 214 may subsequently be formedcontaining the blocking agent in the pores or interstices of the rock,sand or soil of the layer 204 adjacent to or in contact with theinterface 205 between the layers 202 and 204. While reference is made toregion 214, it will be appreciated that the blocking agent will, infact, occupy pores or interstices in the solid components of the layerand thus will not normally form an exclusively liquid body in theregion. Although not shown, a further well or wells may be drilled intothe water and/or gas containing layer 204 to remove water and/or gas asthe blocking agent is being injected into the layer, thereby providing auniform displacement of fluids. Such further well or wells may bepositioned higher in the layer 204 than the blocking agent injectionwell 210 to avoid withdrawal of the blocking agent itself. The well(s)may be in the vicinity of injection well 210 to provide the necessary“venting” effect effective for fluid displacement. As noted, the region214 containing the blocking agent introduced via injection well 210 maybe created before the SAGD process is commenced, or at least beforesignificant heat from the SAGD process permeates the water and/or gascontaining layer 204. The blocking agent may be such that it remainsfluid at the initial ambient temperatures normally found within suchreservoirs, e.g. 6 to 15° C., for extended periods of time, e.g. severaldays, weeks or months.

The SAGD process is operated by injecting steam into the oil-containinglayer 202 through the injection well 206 to heat the formation and tocreate a steam chamber 216 that expands in volume as the geologicalformation is gradually heated by the steam. The steam heats the heavyoil within the porous substrate and consequently the heavy oil becomesmore fluid and descends within the formation so that it can be removedvia the production well 208, e.g. by pumping. Pores partially drained ofheavy oil in this way are occupied by further steam to expand the steamchamber 216. By heat conduction, the steam within the steam chamber alsocreates a heated zone 218 in the rock or soil formation above the steamchamber itself, and this eventually penetrates into the region 214containing the blocking agent within the water and/or gas containinglayer 204. The thermally-activated blocking agent within the region 214is such that, when it is exposed to heat from the steam, it hardens,solidifies, precipitates solids, densifies, gels, or otherwise creates afluid-blocking seal 220 above the heavy oil containing layer 202,thereby blocking pores within the rock, sand or soil formation. The sealrestricts or prevents the flow of fluids. The seal serves to isolate,either partially or fully, the heavy oil containing layer 202 from thewater and/or gas containing layer 204, at least in the region of thesteam chamber 216 formed around the injection well 206. The seal mayminimize or prevent the water and/or gas containing layer 204 fromacting as a “thief layer” that nullifies the effects of the steam andpressure used for the SAGD process. The seal may therefore enableimproved recovery of heavy oil. The blocking seal 220 may help toprevent water from layer 204 descending into the steam chamber 216 andheated zone 218 and causing an undesired cooling effect.

It has been stated above that the blocking agent injection well 210 maybe positioned close to the interface 205. However, sometimes theblocking agent may be injected close to the top of a water and/or gascontaining layer, or at least significantly above the interface 205, andallowed to descend under gravity through the pores or intersticestowards the interface. The blocking agent may be injected close to thetop when layer 204 forms a gas cap. Gas is less likely to prevent thedescent of the blocking agent than water. If there is a layer of highpermeability within the gas cap, the injection of the thermally and/orchemically-activated blocking agent may target the high permeabilitylayer. Target the high permeability layer may aid in ensuring that theblocking agent is well distributed above the SAGD wells 206, 208.

While one blocking agent injection well 210 may be provided for eachsteam injection well/production well pair 206, 208 (i.e. the SAGDwells), a single blocking agent injection well 210 may be provided fortwo or more such well pairs. The single blocking agent injection well210 may be provided when the blocking agent injection well is suitablypositioned (e.g. mid-way between and above two adjacent well pairs)and/or is of such a capacity for fluid delivery relative to thepermeability of the substrate, to provide a blocking agent region 214extending above such multiple pairs of SAGD wells. Moreover, while theblocking agent injection well 210 may be horizontal or close thereto asshown, the blocking agent injection well 210 may alternatively bevertical or more angularly sloped. The blocking agent injection well maybe vertical or more angularly sloped if the resulting blocking agentregion 214 forms above the heavy oil containing layer 202 in the regionof the steam chambers formed by one or more pairs of SAGD wells to forman effective seal for all such SAGD wells.

The blocking agent 212 may be in the form of a liquid, e.g. a solutionor emulsion, or in the form of a flowable slurry or gel, or in any otherform that allows the blocking agent to be injected (e.g. allowed to flowunder gravity or pumped) into the relevant layer to form an extensiveregion 214 containing the blocking agent which forms a seal when theblocking agent is transformed. The SAGD process is then capable ofoperating as it would in an equivalent reservoir having a relativelyimpermeable layer positioned above the heavy oil containing layer 202.

It will be understood that FIGS. 2A to 2D show an extremely simplifiedillustration of an underground reservoir in that the interface 205 maynot be a distinct flat horizontal stratum as shown, but may vary inthickness (i.e. have varying heavy oil, water and/or gas content overits height) and may be of complex shape or arrangement. Moreover, theseal 220 formed at the interface may not be always form complete barrierto steam, gas and water, but may only increase the resistance to thepenetration of such fluids through the seal. The seal may of course besuch that the increase in such resistance produces a measurable increasein heavy oil recovery compared to the absence of such a seal in the samereservoir formation.

FIGS. 3A and 3B illustrate a procedure in which two blocking agents ofdifferent categories or types are injected into a formation to form aneffective seal. In the case of FIG. 3A, the arrangement is similar tothat of FIG. 2A but an additional blocking agent injection well 310 hasbeen drilled into the water and/or gas containing layer 204 above theoriginal blocking agent injection well 210. A heat-activated blockingagent 212 of the kind having inverse solubility characteristics isinjected through input well 210, as before, to produce a blockingagent-containing region 214. A second blocking agent 312 of a differentkind, e.g. a chemically-activated blocking agent or athermally-activated blocking agent of the type having normal solubilitycharacteristics, is then injected into layer 204 through the additionalblocking agent injection well 310. The second blocking agent 312 forms aregion 314 overlying and extending horizontally beyond the margins ofthe region 214 containing the first-injected blocking agent 212. Thefirst blocking agent may be activated by heat from a SAGD process in themanner shown in FIGS. 2C and 2D to form a seal. The second blockingagent 312 may be present to extend the seal in the regions where thereis insufficient heat from the SAGD process to activate the blockingagent 212, or where reactive gases such as CO₂ escape from the heavy-oilcontaining layer 202 during the SAGD process.

In the case of FIG. 3B, as in FIG. 2A, there is only a single blockingagent injection wellbore 210 drilled into the water and/or gascontaining layer 204. A first thermally-activated blocking agent 212having inverse solubility characteristics may be injected into the layerthrough the wellbore 210. The first blocking agent 212 may be allowed todescend to the level of the interface 205 to form a first blocking agentcontaining region 214. A second blocking agent 312 of a different kind,e.g. a chemically-activated blocking agent or a thermally-activatedblocking agent having normal solubility characteristics, may then beinjected into the layer 204 through the same wellbore 210 to form asecond blocking agent containing region 315 overlying and surroundingthe region 214, just as in the case of FIG. 3A. The arrangement of FIG.3B avoids the extra cost of drilling the additional wellbore 310 of FIG.3A and is advantageous if the rock, sand or soil substrate of layer 204is sufficiently porous to allow rapid and uniform percolation of thefirst-injected blocking agent 212 through the layer towards theinterface 205. It may also be advantageous to drill the injectionwellbore 210 slightly higher in the layer 204 in the case of FIG. 3B toallow room above the interface 205 and below the wellbore 210 toaccommodate the entire region 214.

While detailed information has been provided above, it will beunderstood that numerous changes, modifications, and alternatives to thepreceding disclosure can be made without departing from the scope of thedisclosure. The preceding description, therefore, is not meant to limitthe scope of the disclosure. Rather, the scope of the disclosure is tobe determined only by the appended claims and their equivalents. It isalso contemplated that structures and features in the present examplescan be altered, rearranged, substituted, deleted, duplicated, combined,or added to each other in any effective manner.

The articles “the,” “a” and “an” are not necessarily limited to meanonly one, but rather are inclusive and open ended so as to include,optionally, multiple such elements.

What is claimed is:
 1. A method of recovering heavy oil from ahydrocarbon reservoir in which a water and/or gas containing layeroverlies a heavy oil containing layer, the method comprising: providingan injection well in said water and/or gas containing layer above atleast one pair of horizontal wells in said heavy oil containing layerfor heavy oil recovery by a steam assisted gravity drainage process;injecting a first blocking agent into said water and/or gas containinglayer via said injection well to form a first region of said waterand/or gas containing layer containing said first blocking agentadjacent an interface between said water and/or gas containing layer andsaid heavy oil containing layer above said at least one pair ofhorizontal wells; and operating said steam assisted gravity drainageprocess via said at least one pair of horizontal wells by injectingsteam into said heavy oil containing layer and recovering heavy oil fromsaid heavy oil containing layer; wherein said first blocking agent isinjected into said water and/or gas containing layer before operatingsaid steam assisted gravity drainage process or before heat generated bysaid steam assisted gravity drainage process reaches said first regionof said water and/or gas containing layer; and wherein said firstblocking agent, when present in said first region, undergoes a change ofviscosity, density or solidity when elevated to a temperature between aninitial ambient reservoir temperature in said first region and 175° C.by heat from steam used in said steam assisted gravity drainage process,and thereby creates a seal within the hydrocarbon reservoir above saidat least one pair of horizontal wells limiting or preventing movementsof fluid through said seal.
 2. The method of claim 1, wherein said firstblocking agent is in a form selected from the group consisting of aliquid, a flowable slurry, and a gel.
 3. The method of claim 1, whereinsaid first blocking agent is in a form of a liquid selected from thegroup consisting of a solution and an emulsion.
 4. The method of claim1, wherein said first blocking agent has inverse-solubilitycharacteristics such that the first blocking agent is configured toincrease in viscosity, density or solidity with increase of temperature.5. The method of claim 1, wherein said first blocking agent increases inviscosity, density or solidity to form said seal within the reservoirwhen heated by heat from said steam to a temperature between initialambient temperature of said first region and about 125° C.
 6. The methodof claim 1, wherein said first blocking agent increases in viscosity,density or solidity to form said seal within the reservoir when heatedby heat from said steam to a temperature between initial ambienttemperature of said first region and about 100° C.
 7. The method ofclaim 1, wherein said first blocking agent comprises an aqueous solutionof sodium silicate.
 8. The method of claim 7, further comprisingintroducing an additive into said aqueous solution, said additive beingat least one compound selected from the group consisting of acids,chelating agents, pH modifiers and anti-scalants.
 9. The method of claim7, wherein said sodium silicate is present in said aqueous solution at aconcentration in a range of 1 to 10 wt. %.
 10. The method of claim 7,wherein said sodium silicate is present in said aqueous solution at aconcentration in a range of 3 to 5 wt. %.
 11. The method of claim 1,wherein said first blocking agent comprises an aqueous solution ofsodium bicarbonate.
 12. The method of claim 1, wherein said firstblocking agent comprises colloidal silica.
 13. The method of claim 1,wherein said first blocking agent comprises a solution of silica and asoluble compound of a metal selected from the group consisting of Ca, Mgand Fe that forms insoluble metal silicates when subjected to heat fromsaid steam.
 14. The method of claim 1, wherein, after injecting saidfirst blocking agent into said water and/or gas containing layer, asecond blocking agent is injected into said water and/or gas containinglayer to form a second region above said at least one pair of horizontalwells, said second blocking agent undergoing an increase of density,viscosity or solidity when situated within said second region.
 15. Themethod of claim 14, wherein said second blocking agent is injected intosaid water and/or gas-containing layer via said injection well used forinjection of said first blocking agent.
 16. The method of claim 14,wherein said second blocking agent is injected into said water and/orgas-containing layer via at least one injection well different from saidinjection well used for injection of said first blocking agent first.17. The method of claim 14, wherein said second blocking agent is athermally-activated blocking agent having normal solubilitycharacteristics such that said second blocking agent is configured toincrease in viscosity, density or solidity with decrease of temperaturewhen injected at elevated temperature into said water and/or gascontaining layer.
 18. The method of claim 14, wherein said secondblocking agent comprises an aqueous solution of silica injected intosaid water and/or gas containing layer at an elevated temperature abovesaid ambient reservoir temperature.
 19. The method of claim 18, whereinsaid elevated temperature is a temperature of at least 80° C.
 20. Themethod of claim 1, wherein said steam assisted gravity drainage processcomprises: injecting steam into said heavy oil containing layer via anuppermost one of said at least one pair of horizontal wells to heatheavy oil in said heavy oil containing layer to reduce viscosity of saidheavy oil; and removing the heavy oil from said heavy oil containinglayer via a lowermost one of said at least one pair of horizontal wells.